The field of this invention is the removal of fluids from wellbores using high volume and high reliability pumping or artificial lift systems. In the prior art, examples of which are cited below, it is known to use reciprocating linear pumps installed in line at the bottom end of a wellbore, attaching conduit between the pump and surface collection equipment, and powering the reciprocal motion of the pump, typically of pistons deployed within a cylinder with associated flow valve controls such as one-way valves to control fluid flow within the pump subassembly, by a series of sucker rods connected end-to-end and attached at the lowest end to the pump subassembly, and at the highest end to some mechanism such as pump jack or similar drive mechanism providing reciprocating linear motion under power from surface to the pump subassembly. The linear pumps may be a series or stages of lift pistons and packers with suitable one-way valves at each stage. These systems are time-worn, time-tested, and provide high reliability, but cannot be deployed in deviated wellbores (commonly referred to as ‘horizontal wells’), due to the inability of a series of rigid interconnected rods to move linearly around the corner or bend in a deviated wellbore without impacting the well's inner wall, causing damage and wear to both casing and the rod system. Additionally, pump-jack style lift systems provide a very uneven pressure profile and relatively low and uneven flow rate of produced fluid, resulting in lower pumping volumes and inefficiencies. These pumps are very common and form part of the common general knowledge within the field of the invention.
Newer systems substitute the pump-jack with a linear hydraulic motor at surface, with associated control systems to try to even out the uneven production flow caused by uneven motor loads and mechanical connections introduced to the power strokes within the extension and contraction of the thousands of feet long rod string, whereby motor power from surface is hoped to be more effectively transferred to the downhole pump with a more finely controlled linear motor rather than the previous crude pump jack systems, or via hydraulic fluid power instead of via the rod string to transfer reciprocating linear movements, and thereby it is hoped to improve the low pumping rate and efficiency of conventional pump jack systems. An example of this may be seen in US2015/0285041 Dancek and U.S. Pat. No. 8,851,860 to Mail. In this type of improved pump system, it is the power supplied at surface to drive the same type of sucker rod pumping systems downhole which is the novelty: by using a hydraulic ram to provide reciprocating linear drive to the sucker rods, and controlling the hydraulic ram with adaptive control systems, the power profile and stroke length and cycle times can be more finely tuned with computer-based adaptive code and pressure and flow sensor information. These systems cannot be deployed in deviated wellbores, and provide for hydraulic switching valve controls at surface and not at the pump. This helps to improve the flow volume characteristics which were failings of the pump-jack prior art, and provides a well-head with no large moving parts, making it less unsightly and presumably safer for people to be around. The thousands of feet long rod string of these prior art inventions still has to reciprocate, which wastes much of the driving energy through the potentially miles long, mechanically jointed, friction-prone and connected rod string, and tons of mass of rod mechanism to supply the linear power to the downhole pump. Wellbore fluid pressures still fluctuates a large amount at each reciprocating stroke of the pump plunger's suction and discharge actions, which will disturb the filtered sands around the wellbore's screens or slotted liners, and cause those contaminants to be sucked into the pump chamber, accumulating and blocking the pump valves. In order to prevent rod friction and wear with the wellbore's inner surface or casing, the downhole pump of these inventions cannot be placed deep down in a deviated well section or in a horizontal well production zone, which means these systems may have to be supplemented with ESP systems when the well's fluid production declines.
Other systems use hydraulic pressure provided from surface equipment via conduits (spaghetti hose) to power linear movement in reciprocating linear pumps in lower sections of an associated wellbore, but are controlled by mechanically tripped or triggered switching valve gear included in the pump and actuator at the well's bottom end, or else have their switching valves at surface.
Some new systems provide for conventional submersible piston/cylinder reciprocating pump bodies powered by a downhole hydraulic cylinder actuator deployed at and above the conventional reciprocal pump, and powered by hydraulic pressure provided from surface via two conduits, switching between power fluid pressure and hydraulic fluid exhaust, with each conduit providing both functions, being switched by control gear and valve systems at surface, actuated by pressure sensing means also at surface. The pressure sensor means provides a signal when pressure in the conduit providing high pressure hydraulic power becomes elevated (inferring the end of that power stroke), in response to which the hydraulic fluid flow in the two conduits is reversed. A variety of problems arise: the equipment suffers some of the issues with the other new systems, being susceptible to water-hammer effects and power loss due to the reversal of fluid flow direction at the end of each stroke—bear in mind that the hydraulic fluid conduits are in the range of several thousands of feet in length, which is a large volume (and mass) with large inertial forces; the actuator itself will be subject to a wider range of pressures (lower low pressure regime in the side of the pump being evacuated prior to becoming supplied with pressured hydraulic fluid, higher pressure regime when the piston is at the end of a power stroke while the momentum of hydraulic fluid continues after being switched at surface but before being relieved by its associated hydraulic conduit becoming an exhaust conduit in function by switching at surface), and all fittings associated with the hydraulic lines, connections and et cetera will be subjected to large forces (larger than strictly required to power the reciprocation of the actuator's piston). Additionally, there is an inevitable timing lag between the increase in pressure at surface and the actual reversal of power fluid flow which affects the volume and pressure flow characteristics of the produced fluid in the system; further, the conventional submersible pumps and the configuration of the actuator in these systems are constrained by their relative location (order) and the inside diameter of the wellbore and production tubing at their location, meaning that the actuator being above the pump restricts the volume or cross-section of the bore through which the produced fluid must flow past the actuator. An example of this type of arrangement is found in CA 2,258,237
U.S. Pat. Nos. 6,623,252 B2, 6,004,114, and Canadian Application 2,258,237 all by Edmund C. Cunningham are a different rod-less solution for a downhole pump which can be placed in a deviated well's slanted or horizontal production section. Those new methods apply hydraulic power to drive the downhole pumps by a downhole hydraulic rotary motor or a downhole reciprocating hydraulic actuator. In those disclosures, the thousands of feet long sucker rod string is removed, and a downhole electrical motor (ESP) is replaced with a hydraulic motor or hydraulic reciprocating actuator. There are also some examples in Alberta Oil Sand CSS or SAGD wells that use hydraulic rotary motors to drive metal to metal Progressive Cavity Pumps (PCP) or multi-stage centrifugal pump systems. All of those examples have made some changes to the pump drive or power mechanism and do not make any change to the downhole pumps themselves, but either use traditional PCP pumps or conventional reciprocating pumps placed within the production tubing. These pumps' flow rate are usually small and cannot achieve the large flow rate that a similar size and diameter ESP could generate or rates which producing SAGD wells really require. The CA 2,258,237 disclosed invention will actually be a failure in use. It proposes that a double acting hydraulic submersible actuator is controlled by a ground surface valve system to reciprocate and automatically reverse a conventional downhole pump. As noted above, the hydraulic supply tubing from the surface equipment to the downhole pump will be at least a few thousand feet long for most oil wells. Such an arrangement of switching hydraulic flow direction at surface will most likely result in be a default “top dead center”. In addition, as noted above, when the hydraulic actuator's piston stroke reaches one end of its travel, the surface switch will not automatically or immediately reverse the flow of thousands of feet of hydraulic fluid and the inertial energy stored in the long tubing of hydraulic fluid will continue to flow forward at the lower end of the supply tubing and into the already full pump chamber, which would cause a large pressure surge in the hydraulic actuator's one chamber. From the other actuator chamber to surface inside the hydraulic exhaust tubing, the hydraulic fluid, typically an oil, in the tubing continues to deplete, which creates a liquid column separation partial vacuum which can lead water hammer forces and deterioration of the hydraulic fluid by the partial vacuum.
It is apparent that there is a need to address at least some of the above mentioned problems of the prior art.